Attachment

UTILITY COMMITTEE AGENDA JANUARY 23, 2012 - 6:00 P.M. CITY HALL COUNCIL CHAMBERS 15 LOOCKERMAN PLAZA DOVER, DELAWARE Public comments are welcomed on any item and will be permitted at appropriate times. When possible, please notify the City Clerk (736-7008 or e-mail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. Request for Alley Abandonment (Unimproved) - 16 Sackarackin Avenue - Alexis Bailey 2. Reconsideration - Cost of Service Study 3. TEA/NAES Monthly Reports (October and November) 4. Updates A. National Pollution Discharge Elimination System (NPDES) Municipal Separate Storm Sewer Systems (MS4) Permit B. Calpine Corporation Project (Garrison Oak Technical Park) 5. Adjournment by 6:25 P.M. /tm S:\AGENDAS & MINUTES\Committee-Agendas\2012\01-23-2012 UTILITY.wpd THE AGENDA ITEMS AS LISTED MAY NOT BE CONSIDERED IN SEQUENCE. THIS AGENDA IS SUBJECT TO CHANGE TO INCLUDE THE ADDITION OR THE DELETION OF ITEMS, INCLUDING EXECUTIVE SESSIONS.

ACTION FORM PROCEEDING: Utility Committee DEPARTMENT OF ORIGIN: City Manager’s Office DATE SUBMITTED: 01-13-2012 PREPARED BY: Scott D. Koenig, P.E., City Manager SUBJECT: Request for Alley Abandonment (Unimproved) – 16 Sackarackin Avenue – Alexis Bailey REFERENCE: RELATED PROJECT: N/A REVIEWED BY: EXHIBITS: Exhibit A - Request from Alexis Bailey; Exhibit B - Site Map TIME TIMETABLE: The City Solicitor will prepare a deed once approved by City Council. RECOMMENDED ACTION: Recommend approval of the alley abandonment, reserving a utility easement for future utility installation on the property should it be necessary. BACKGROUND AND ANALYSIS City staff has received a written request from Ms. Alexis Bailey regarding the abandonment of the unimproved paper alley adjacent to her home located at 16 Sackarackin Avenue. Ms. Bailey is requesting abandonment of the alley in hopes that she will be able to construct a permanent driveway on her property in the future. Staff has reviewed the request and there are no objections to the abandonment of the paper alley adjacent to this property. Staff will require that a public utility easement be retained in this area in case future utility projects would need the space. The construction of a driveway within the easement would be allowed. The staff analysis and recommendation is based upon our internal review and does not include contact with adjacent property owners. Any legal expenses associated with the abandonment of the paper alley will be paid by the property owners.

16 Sackarackin Avenue Proposed Alley Abandonment §Ò ! 631 × 75 63 §Ò §Ò ! ! 53 59 55 51 33 . ! 41 §Ò 803 39 !§Ò ! ! §Ò !§Ò 805 ! ! ×Ò §Ò§ §Ò Ave ! a r a ckin §Ò 807 §Ò ! Sack ! ! §Ò 76 §Ò 72 ! 64 68 §Ò §Ò !! ! . §Ò ! 60 40 54 × §Ò ! 50 46 ! §Ò 901 36 20 28 16 !§Ò 903 915 921 §Ò ! 955 × §Ò ! 0 87.5 175 350 Feet §Ò × ! ¯ Legend Date Printed: December 9, 2011 §Ò ! Overhead Electric Pole Hydrants File: m:\gis_data\projects/tech_mxds × . ! Manholes \street_abandonment_sackarackin_ave Underground Electric Lines Sewer Line Department: Public Services GIS Overhead Electric Lines Right of Way to be Abandoned City of Dover, Delaware Water Main Dover Parcels Hydrant Line

List of Adjacent Property Owners of Alley Abandonment Sackarackin Ave. 1-19-12 PARCEL ID Property Address OWNER Owner Address Owner Address 2 City State Zip Code ED05-077.13-02-57.00 54 SACKARACKIN AVE WEYANDT,DOROTHEA C 54 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-58.00 50 SACKARACKIN AVE LECHNER,KAREN A 50 SACKARACKIN AVE DOVER DE 19904 ED05-077.13-02-59.00 46 SACKARACKIN AVE MCNEIL,JACCQUELINE H 46 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-52.00 76 SACKARACKIN AVE ARELLANO,LAMBERTO M MD & LYZBETH M REVOC TRUST 1 PHEASANT LN CAMDEN WYOMING DE 19934 ED05-077.13-02-60.00 40 SACKARACKIN AVE SEEMAN,LAWRENCE J & STEPHANIE 40 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-56.00 60 SACKARACKIN AVE OLECHNY,WILLIAM T & KATHRYN N 60 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-67.00 915 S STATE ST PEPPER,JEANNE C 915 S STATE ST DOVER DE 19901 ED05-077.13-02-55.00 64 SACKARACKIN AVE GARRETT,JANET W & SPALLUTO,ELIZABETH M 64 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-61.00 36 SACKARACKIN AVE MORRIS,ELIZABETH B 36 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-62.00 28 SACKARACKIN AVE SHORT,MARGARET A 28 SACKARAKIN AVE DOVER DE 19901 ED05-077.13-02-53.00 72 SACKARACKIN AVE WOHLGEMUTH,CHARLOTTE 72 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-54.00 68 SACKARACKIN AVE LEHTO,NANCY P 68 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-66.00 903 S STATE ST HYNES,EDWARD J & PATRICIA S 903 S STATE ST DOVER DE 19901 ED05-077.13-02-69.00 955 S STATE ST DOVER SPECIAL SCHOOL DISTRICT 945 FOREST ST DOVER DE 19904 ED05-077.13-02-63.00 20 SACKARACKIN AVE HARVEY,ASHLEE M & HARVEY,EMILY & HARVEY,JONATHAN T 1530 E BALTIMORE ST BALTIMORE MD 21231 ED05-077.13-02-64.00 16 SACKARACKIN AVE BAILEY,ALEXIS L 16 SACKARACKIN AVE DOVER DE 19901 ED05-077.13-02-65.00 901 S STATE ST FORAKER,DOROTHY Y 901 S STATE ST DOVER DE 19901

1 of 5 ACTION FORM PROCEEDING: Utility Committee Meeting – January 23, 2012 DEPARTMENT OF ORIGIN: Finance Department DATE SUBMITTED: 01/17/12 PREPARED BY: Donna Mitchell, Controller/Treasurer SUBJECT: Electric – Cost of Service & Rate Design Study REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: Committee/Council EXHIBITS: N/A EXPENDITURE REQUIRED: $28,500 TIMETABLE: To Be Completed by April 30, 2012 RECOMMENDED ACTION: As outlined in the attached proposal, staff recommends the Cost of Service and Rate Design Study for FY 12.

2 of 5 January 4, 2012 Ms. Donna Mitchell, CPA Controller/Treasurer City of Dover 5 E. Reed Street Weyandt Hall, Suite 300 Dover, DE 19901 Re: Proposal to Perform an Updated Electric Cost-of-Service and Rate Design Study Dear Ms. Mitchell: As a result of our recent discussion on December 22, 2011, Burns & McDonnell is providing this letter proposal to complete the 2012 Electric Cost-of-Service and Rate Design Study (Study) for the City of Dover Electric System (the Electric System). Burns & McDonnell is pleased to submit this letter proposal to perform the desired services for the City of Dover (the City) and the Electric System. Based upon our previous involvement in performing cost-of-service analysis and electric rate design for the Electric System, we believe that we are eminently qualified to perform the Study to the complete satisfaction of the City and the Electric System. Presented herein is our proposal. Project Understanding The Study is necessary to address specific issues associated with allocating costs of system operations including purchased power and developing rates designed to incorporate costs of providing service to various customer classes of the Electric System. The following guidelines and special issues will be of principal importance in performing the Study: 1. The rates to be developed must recover the Electric System’s revenue requirements. 2. The rates to be developed must be fair and equitable across customer classes. 3. The rates to be developed and the implementation schedule for those rates must be reasonable. 4. Power supply costs will be allocated to both demand and energy based on an estimate of the inherent capacity included in the current power supply arrangement and will be modeled accordingly in the financial analysis and cost-of-service model. 5. The Study will address any specific changes to customers that need to be made for the demand components and any corresponding changes to energy charges. Burns & McDonnell will make use of the analysis and model prepared in previous rate study efforts completed for the City and the Electric System. We will make revisions to forecasts prior to completing the updates to the cost-of-service allocations and the preparation of rate designs to be completed through this Study. Scope of Work The major elements of the proposed Scope of Work include the following: 1. Update Revenue Requirements Analysis 2. Develop Current Cost-of-Service Model Analysis 3. Prepare Necessary Revisions to Electric Rates 9400 Ward Parkway • Kansas City, MO 64114-3319 Tel: 816 333-9400 • Fax: 816 333-3690 • www.burnsmcd.com

3 of 5 Ms. Donna Mitchell, CPA City of Dover January 4, 2012 Page 2 of 4 1. Update Revenue Requirements Analysis We will update the financial forecast model previously developed by Burns & McDonnell and currently being utilized by the City. The financial forecast update will be used to determine the adequacy of revenues for a five-year forecast period. The updated forecast will include projections of annual revenues under existing rates and the annual revenue requirement, including purchased power costs, all operating expenses, capital requirements, debt service requirements, and reserve requirements, by year for the forecast period. The financial plan developed will identify the overall change in revenue required to provide for adequate funding for capital improvement programs, to meet all recurring annual operating and capital expenditures, to cover all debt service requirements, to maintain sufficient cash balances and capital reserves, and to address costs associated with purchased power supply. Information developed in previous electric rate studies and analysis will be utilized in the revised forecast and financial plan. Prior to finalization of the financial plan, the City and Burns & McDonnell will agree on the revised financial forecast model results and the assessment of estimated impacts on the cash flow of the Electric System. 2. Develop Current Cost-of-Service Analysis Burns & McDonnell will complete an update to the cost-of-service analysis to identify the relative responsibility of each rate classification for the recovery of th e Electric System costs of service. The cost- of-service analysis will be completed using FY 2012 as the test year. The cost-of-service analysis will include development of appropriate allocation factors based on statistical units of service and allocation methodologies. In order to verify that revenue is recouping the cost of product or services rendered, all sources of revenue will be reviewed. Information developed in the most recent electric rate study will be utilized in conducting this analysis. The key aspect of this analysis will be the cost allocation regarding the power supply arrangements and allocating this cost between demand and energy requirements. The cost-of-service analysis will provide for the unbundling of costs to specific functions. The specific unbundled functions that will be developed include:  Demand  Distribution Delivery  Energy  Customer Service  Transmission Delivery The analysis will also provide allocation of appropriate costs to specific customer classes. 3. Prepare Necessary Revisions to Electric Rates Burns & McDonnell will perform an evaluation of potential rate revisions for consideration by the City. This phase of the Study will be the most demanding due to the specific objectives which must be met in the design of rates. This phase of the Study will require extensive communication and coordination with the City. Work Plan The following tasks are proposed to be undertaken by Burns & McDonnell as a method for completing the Study.

4 of 5 Ms. Donna Mitchell, CPA City of Dover January 4, 2012 Page 3 of 4 Task 1 - Initiate Project Task 1.1 Prepare Data Request Task 1.2 Project Kick-off Conference Call Task 2 – Update Review Revenue Requirements Analysis Task 2.1 – Review Financial Forecast Model Provided by the City Task 2.2 – Review Projected Operating & Capital Costs Task 2.3 – Adjust Financial Model as Necessary Task 2.4 – Develop Cash Flow Analysis Task 3 - Develop Current Cost-of-Service Analysis Task 3.1 – Determine Utility Cost Assignments Task 3.2 – Allocate Functional Costs Task 3.3 – Review Cost-of-Service Results Task 4 – Prepare Necessary Revisions to Electric Rates Task 5 – Prepare Study Report and Deliver Results Upon completion of the review of the revenue requirements, development of the FY 2012 cost-of-service model, and rate evaluation and design, Burns & McDonnell will summarize the Study results for the Electric System in a preliminary report for review by the City and Electric System. Two (2) copies of this report will be provided. The report will describe the analysis completed and will identify the inputs, assumptions, methodology, and results of the Study. It will also contain recommendations for how the City should proceed with implementation of the Study recommendations. Burns & McDonnell will discuss the results of the Study in a meeting with City and Electric System staff. Based upon comments and input from the City and Electric System, Burns & McDonnell will revise the final report, as appropriate, and will provide ten (10) copies of the final report to the City. An electronic copy of the report will also be provided in Adobe Acrobat format. Burns & McDonnell will also be prepared to present the Study results to City Council if desired. This pres entation is an optional service and as such, costs have not been included in the estimate provided below. Proposed Budget Burns & McDonnell proposes to perform the Study for an estimated fee of $28,500. The estimated fee is based on approximately 176 man-hours for completing the required Study efforts. This estimate includes appropriate project conference calls and one project trip for the project manager and project engineer/analyst. If the work can be completed for less than the estimated fee, the City will only be billed for the actual costs incurred to complete the Study. This fee does not include costs associated with providing a presentation of the Study results to City Council. Proposed Schedule Burns & McDonnell proposes to initiate work on the proposed services upon notice to proceed. Work on the review of revenue requirements will be completed during the first month of the project. The cost-of- service model will then be completed over the next month. The first draft of proposed rates will be

5 of 5 Ms. Donna Mitchell, CPA City of Dover January 4, 2012 Page 4 of 4 submitted to the City in late-March and final rate design is expected to be completed by the end of April assuming City and Electric System staff can complete the necessary rate testing in a timely manner. The Study report will be submitted in a timely manner to meet the specific requirements identified by the City. We expect the report will be submitted within two weeks after final approval of rate adjustments. Burns & McDonnell is grateful for the opportunity to provide the City of Dover continued service in these important matters. Should you have any questions regarding the material presented herein please call Ted Kelly at (816) 822-3208. If this proposal for the updated cost-of-service and rate design services is acceptable please indicate by signing below and returning one copy of the proposal letter. Respectfully Submitted, Jeffrey J. Greig General Manager, Business & Technology Services Ted J. Kelly Principal, Business & Technology Services JJG/TJK Authorization for 2012 Electric Cost-of-Service and Rate Design Study Accepted by:

The Energy Authority, Inc. Monthly Management Committee Update – October 2011 November 22, 2011 Prepared by: Jamie Mahne Member Services Manager 904.360.1374 jmahne@teainc.org

TABLE OF CONTENTS I. Executive Summary ................................................................................................................ 1 II. Budget Report ......................................................................................................................... 4 III. Energy Management ............................................................................................................ 7 IV. Operations Management .................................................................................................... 14 i

I. Executive Summary Power Supply: Powers Supply costs were $497,809 under budget due to lower load than forecast and lower than forecasted PJM prices. Average cost/MWh on the supply side was $82.91 compared to a budgeted cost of $88.82. Dover’s hedge purchases totaled 51,000 MWh, which was 88% of the projected load. Versus actual load, this hedged percentage totaled 90% of Dover’s needs for the month. Dover’s power purchases from hedge transactions totaled $3,302,556. Purchases from PJM totaled $472,554 (all in), with DA Energy purchases totaling $107,716 and Balancing Spot Market Energy totaling $36,275. 1

Generation Summary Dover did not generate electricity for PJM in the month. This was consistent with the budget. Net generation revenue was $281,061 vs. a budget of $185,931. The majority of this delta was due to lower than expected O&M costs. Operations Management Summary During the month of October, there were no reportable or lost time accidents or injuries. The facility has now gone 382 days without an OSHA recordable accident and 382 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There was one Near Miss incident which involved the venting of the Unit 3 main gas line in preparation for work to be performed during the outage. The near miss related to operating procedures not being updated to reflect new venting policy. In the month of October, McKee Run Units 1,2, and 3 and VanSant Unit 11 were not dispatched. All units were in outage starting October 3. One NOx annual allowance was sold on October 28. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of October were $348,515. The expenses were $73,467 or 17.41% under the approved budget of $421,982. The principal reason for the favorable variance is due to lower labor and burden costs attributable to open staff positions and employee incentive accumulator costs budgeted in October to be paid in June 2012. These favorable variances were offset by increased costs for electricity, contract services and training. 2

Risk Management Summary Forward power prices in PJM have been falling throughout October and into November, but not as steeply as natural gas prices have fallen. Subsequently, the PJM heat rate remains very strong. Natural gas storage has risen to the top of the 5 year range. The current projected cost of service is below: Power Year Hedge Ratio Blended Cost ($/MWh) 2011-12 83% $70.45 2012-13 74% $67.32 2013-14 46% $59.93 2014-15 24% $59.05 2015-16 3% $62.86 3

II. Budget Report Variance Report: Budget Actual Variance Oct-11 Oct-11 Load Forecast (Net of Solar Output) 58,231 56,376 1,855 Power Supply Power Supply (inc. Mgt Fees) $4,476,284 $3,964,534 $511,750 Capacity UCAP Obligated Purchased $695,864 $709,804 ($13,940) Total - Power Supply $5,172,147 $4,674,338 $497,809 Power Generation O&M & Fixed Fuel Plant O&M $421,982 $348,515 $73,467 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation O&M & Fixed Fuel $421,982 $348,515 $73,467 Power Generation Production Margin Economic and reliability dispatch $0 ($1,447) $1,447 Testing $0 $0 $0 Subtotal Generation Production Margin $0 ($1,447) $1,447 Power Generation Non-Production Revenue Generation Capacity Credit ($573,981) ($592,550) $18,569 Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($33,933) ($35,580) $1,647 Subtotal - Non-Production Revenue ($607,913) ($628,129) $20,216 SubTotal - Power Generation ($185,931) ($281,061) $95,130 Total - Utilities Cost $4,986,216 $4,393,277 $592,939 Unit Costs Total - Power Supply $88.82 $82.91 $5.91 Total - Power Generation ($3.24) ($4.99) $1.74 Final Cost of Service to City of Dover Ratepayers $85.58 $77.93 $7.65 4

Variance Analysis: Power Supply Dover consumed 1,855 MWh net (gross load minus solar output) below what was forecasted for the month. The decrease in load and lower than expected prices in PJM resulted in a cost of $82.91/MWh for power supply, $5.91/MWh less than budget. For the month, the city realized a favorable variance of $497,809 for power supply vs. the monthly budget. Dover Sun Park generated 106MWh above what was forecasted. Dover Sun Park did not invoice for any RECs in October. Generation Power generation had a favorable budget variance of $95,130. Plant O&M expenses had a favorable budget variance of $73,467. Power Generation Production Margin realized a favorable budget variance of $1,447, due to Balancing Operating Reserve at PJM being designated as a generation line item. Dover did not sell any generation output to PJM in October. 5

Variance Year-To-Date: Budget Actual Variance YTD YTD Load Forecast (Net of Solar Output) 278,016 277,449 568 Power Supply Power Supply (inc. Mgt Fees) $22,228,213 $21,968,691 $259,522 Capacity UCAP Obligated Purchased $2,761,007 $2,836,457 ($75,450) Total - Power Supply $24,989,220 $24,805,148 $184,072 Power Generation O&M & Fixed Fuel Plant O&M $1,981,143 $1,742,570 $238,573 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation O&M & Fixed Fuel $1,981,143 $1,742,570 $238,573 Power Generation Production Margin Economic and reliability dispatch ($237,844) ($1,724,030) $1,486,186 Testing $0 $0 $0 Subtotal Generation Production Margin ($237,844) ($1,724,030) $1,486,186 Power Generation Non-Production Revenue Generation Capacity Credit ($2,277,407) ($2,135,237) ($142,170) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($135,730) ($186,329) $50,599 Subtotal - Non-Production Revenue ($2,413,137) ($2,321,566) ($91,570) SubTotal - Power Generation ($669,837) ($2,303,026) $1,633,189 Total - Utilities Cost $24,319,383 $22,502,122 $1,817,261 Unit Costs Total - Power Supply $89.91 $90.66 ($0.75) Total - Power Generation ($2.30) ($8.40) $6.10 Final Cost of Service to City of Dover Ratepayers $87.61 $82.26 $5.35 6

III. Energy Management Power Supply Load (MWh) FY 2011-12 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Budget Actual Dover’s total load was 56,376 MWh versus a forecasted load of 58,231 MWh. Dover’s planned hedged volume was 88% of forecast. The decrease in load resulted in a realized hedged volume of 90% of actual load. Dover’s planned energy cost/MWh of unhedged load was $175. The actual energy cost for unhedged load was $117/MWh – this decrease is due to softer than expected PJM prices. Dover’s planned energy purchase from the SunPark solar installation was 1,228 MWh at an all-in unit cost of $100/MWh. Dover’s actual purchase from the SunPark installation was 1,334 MWh at an all-in unit cost of $80. The price discrepancy is due to environmental credits (SRECs) that were produced in October but were not invoiced in October. 7

The following is a summary of Dover’s power purchases for the month: City of Dover's Wholesale Load Volume $'s Hedges 51,000 ($3,302,556.00) PJM Charges 55,042 ($1,182,359.17) TEA Fees ($83,000.00) Dover Sun Park Est. Amt ($157,112.45) Total ($4,725,027.62) Cost to Serve $/Mwh ($85.84) Purchased power variance report: Budget Actual Variance Gross Load 58,231 56,376 1,855 Wholesale Load 57,003 55,042 1,961 Hedged Volume (MWh) 51000 51000 0 Unhedged Volume (MWh) 6,003 4,042 1,961 Hedged Volume (%) 88% 90% -3% SunPark Volume (MWh) 1228 1334 -106 SunPark Energy Cost ($/MWh) $ 100 $ 80 $ 21 Unhedged Energy Cost ($/MWh) $ 175 $ 117 $ 58 Energy Costs ($/MWh) $76.87 $70.32 $6.55 All-in Costs - Energy and Capacity ($/MWh) $88.82 $82.91 $5.91 8

Generation Dover produced no generation in October. Dover’s production margin equaled $1,447. City of Dover's Wholesale Generation Net Generation Mwh 0.00 All In Generation Margin PJM Bill Energy $ 1,447.00 PJM Capacity $ 592,549.50 Black Start, Reactive Credit, DASR & EFORp $ 35,579.51 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Margin $ 629,576.01 Production Margin Generation Production Revenues (PJM) $ 1,447.00 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Production Margin $ 1,447.00 $/Mwh All In Generation Margin $ - $/Mwh Generation Production Margin $ - 9

Fuel Purchases Dover had no fuel purchases in October. Transportation and Imbalance Dover had no transportation or imbalance fees in October. 10

Emissions Emissions and Allowance Management Dover has elected not to include revenues from emission allowance sales in its 2011- 2012 fiscal year budget. Dover has more than sufficient allowances set aside for retirement. Due to the expiration of EPA’s Clean Air Interstate Rule (CAIR) at the end of CY2011, any unused or unsold CAIR allowances will expire without residual value. Emissions Allowance Summary through September 30, 2011 2011-2012 EMISSIONS ALLOWANCE SUMMARY SO2 NOx Allowance Allowance Sale Sale Date Action Rev.1 Allocation2 Rev. Allocation Price Price Seas. Ann. N/A 2003-2006 139 0 0 Carryover 1/1/08 2007 Carryover 549 0 0 1/1/09 2008 Carryover 2,691 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 4 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 3 12/31/09 2009 Emissions (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases Aug 2011 Revised 2010 30 30 ECMPS data Oct 2011 Sale to DMEC $10 (1) 10/31/201 2011 Emissions (2) (32) (36) 1 1 Revenue calculations account for a $0.50/ton broker fee for SO2, a $2/ton broker fee for annual NOx and $1/ton broker fee for seasonal NOx 2 Per Clean Air Interstate Rule (CAIR), starting in 2009, NOx emissions are governed by a seasonal and annual program. 3 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 11

Pre-CAIR: 3,189 TOTAL ALLOWANCES - $10 50 74 - $0 CAIR: 3,976 TEA’s estimate, given current dispatch expectations, for the market value of the remaining CAIR allowance inventory is approximately $9,481 as of November 22, 2011. This represents $3,189 for 3,189 pre-CAIR SO2 allowances trading at $1.00/ton, $2,982for 3,976 CAIR SO2 allowances trading at $0.75/ton, $2,960 for 74 annual NOx allowances trading at $40.00/ton and $350 for 50 seasonal NOx allowances trading at $7.00/ton. EMISSIONS & ALLOWANCE SUMMARY THROUGH OCTOBER 2011 Cumulative Allowances Emissions Cumulative Annual Allowance Allowance sold in Allowance for Sept. Annual Allowances Vintage Allocation October Balance 2011 Emissions Sold 2011 (Purchased) SO2: 2007- 10,157 N/A 131 N/A 4,847 5,179 10 SO2: 2011 1,988 0 2 0 0 1,986 NOx: Ann. 80 N/A 13 1 46 23 2009 NOx: Seas 53 N/A 6 N/A 25 22 2009 NOx Ann. 78 N/A 94.7** N/A (22) 8 2010 NOx Seas 50 N/A 94.7** N/A (53) 10 2010 NOx Ann. 80 0 38.8 0 0 44 2011 NOx Seas 51 0 36.1 0 0 19 2011 Note **: EPA approved petition to use lower emissions rate for NOx on McKee Run Unit 3 by 30 tons. EPA Cross-State Air Pollution Rule or CSAPR The final CSPAR was published in the August 8, 2011 Federal Register (76 FR 48208), with an effective date of October 7, 2011. The first compliance period begins for annual SO2 and NOx allowances on January 1, 2012. CSAPR does not include compliance requirements or allowance allocations for generating units located in Delaware and Dover will not be required to submit emission allowances for annual SO2, annual NOx or Seasonal NOx for compliance years 2012 and beyond. 12

A number of administrative and legal challenges to this new rule have been filed, however TEA cannot foresee the potential outcome of such challenges. TEA has assumed that CSAPR will become enforced as promulgated, thus releasing the City of Dover from having to comply with CSAPR in its current form. The Clean Air Act Title IV provisions for SO2 will remain in effect and Dover, which does not have significant SO2 emissions, will need to continue compliance with this program. SO2 and NOx Prices Due to the collapse of the CAIR allowance market and Delaware not being included in the Cross State Air Pollution Rule market, this section is being discontinued from the Monthly Report. RGGI and Federal Carbon Outlook RGGI spot allowance prices have increased slightly since last month’s report with a price mid-point of $1.90 as of November 22 ,2011. The 13th RGGI auction occurred on September 7th and cleared at the reserve price of $1.89, with only 18% of the 2009-2011 control period allowances offered for sale actually being sold in the auctions. The 14th RGGI auction is scheduled for December 7, 2011. In Congress, there continues to be little movement on climate legislation. EPA continues to pursue the “Tailoring Rule” which will impact new sources and Clean Air Act Title V permitting existing source; however on September 15, 2011 EPA confirmed that it would not meet a September 30 deadline for issuing rules governing greenhouse gas emissions from power plants and other major sources. EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 56260) which requires reporting of greenhouse gas (GHG) data and other relevant information from large sources and suppliers in the United States. The purpose of the rule is to collect accurate and timely GHG data to inform future policy decisions. The implementation program for this rule is referred to as the Greenhouse Gas Reporting Program (GHGRP). The deadline to submit 2010 reports is September 30, 2011. NAES has indicated it submitted the first GHG inventory to EPA in the month of September. 13

IV. Operations Management NAES Corporation Dover, Delaware October 2011 Monthly Report Dave Hodge (left), Senior Operator II, is shown being presented a commemorative PJM polo shirt by Plant Manager Vincent Scire in recognition of achieving PJM System Operator Certification. 14

Table of Contents 1.0 Environmental, Health and Safety 2.0 Financial 3.0 Operations 4.0 Maintenance 5.0 CIP 6.0 General Plant Information 7.0 Summary of NAES Performance 15

1.0 Environmental, Health and Safety: During the month of October, there were no restricted work days or lost time accidents. On October 14, the plant successfully completed one year of being Accident Free. The facility has now gone 382 days without an OSHA recordable accident or a Lost Time reportable accident. The plant received no Notice of Violations (NOVs) during the month. Plant staff members also met with the City of Dover to continue work on an Industrial Pre- Treatment application and permit with Kent County to address the redirection of the cooling tower discharges. There was one Near Miss reported in October which involved the venting of the Unit 3 Main Gas Line in preparation for inspections of the recently installed deck valves. While everyone in the plant had recently completed training on SMP-22, Combustible Gas Purging, Venting and Inerting, steps had not been completed to update all plant operating procedures affected by the new policy, resulting in the Near Miss. This has since been corrected. New spill kits were ordered and put in place to further enhance both the McKee Run and VanSant Generating Station’s Spill Response capabilities. Pre-filled spill kits, each containing response materials specific to the likely spills scenarios, were placed in each of the strategic locations around the plants where these incidents might occur. Environmental, Health and Safety Statistics Month Fiscal Year to Date (October) (7/1/11-6/30/12) NOVs 0 0 Opacity Deviations 0 0 Environmental Deviations 0 3 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 1 4 Man Hours Worked 3,812.92 15,852.17 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 382 Days since last Lost Time Accident 382 16

Emissions (NOx & SO2) All data thru 10/31/11 NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 31.4 1.4 36.1 NOx Summary - Year (Jan. – Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 32.6 2.9 38.8 CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 1 29/30 0/2 earlier 2011 0 75#/48# 5/3 33/31– 3/1 0/0 - 0/0 42#/17# 2/2 Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. Note #- 2 tons (Seasonal and 4 tons (Annual) were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 10/31/2011 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 2010 and earlier 0 4815 276 0 5090* 2011 0 1850 138 1 1988* 2012 0 1850 138 0 1988 17

Note – * Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. CO2 Allowances Summary* CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 59,805 1,699 5,796 55,708 2010 0 47,844 1,636 32,971 16,509 2011 0 35,883 1,227 17,763 19,348 2012 0 23,922 818 0 24,740 2013 0 11,961 409 0 12,370 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 18

2.0 Financial Financial – Current Month Month –October 2011 Actual Budget Variance Personnel 205,823 283,287 77,464 Materials & Supplies 11,123 12,817 1,694 Administrative Expenses 131,569 125,878 (5,691) Total $348,515 $421,982 $73,467 Financial – Fiscal Year to Date (Estimated) Number of Months – 4 Actual Budget Variance Personnel 852,638 1,118,516 265,878 Materials & Supplies 93,503 58,803 (34,700) Administrative Expenses 796,428 803,824 13,087 Total $1,742,569 $1,981,143 $244,265 2.1 Variance analysis: The actual expenses for October are $348,515 against a budgeted amount of $421,982 for a positive variance of $73,467 or ≈ 17.41%. The variance was due to the following: PERSONNEL EXPENSES – Lower Labor, Overtime, and Burdens accounted for a favorable monthly variance of $77,464. There is a positive variance of $31,912 for the Employee Incentive Accumulator and Employee Incentive Burden Accumulator that will occur every month. This is due to the expenses being broken down every month instead of in June when the money is actually expensed. In addition, open positions within the plant contributed to the lower Labor and Overtime expenses. MATERIALS AND SUPPLIES EXPENSES- The accounts with any appreciable variances were the Water Treatment Chemicals, Security-Safety Materials and City Building Maintenance accounts which contributed to a favorable variance of $1,694. ADMINISTRATIVE EXPENSES – Higher than budgeted expenses in the areas of Electric, Training-Conferences-Food, Contractual Services, Fuel-Oil Gas Systems, Combustion Turbine Maintenance and Turbine Generator Systems contributed to an unfavorable variance of $5,691. The latest budget forecast for the current fiscal year is $5,938,116 expensed versus an approved budget of $5,964,818 thereby realizing a 99.55%.expense rate. 19

3.0 Operations Unit Operations / Outages / Trips McKee Run and VanSant Generating Station were in a Planned Outage status for most of the month of October, so no units were dispatched. The outage started on October 3, 2011 and is expected to be completed on December 2, 2011. Month – October 2011 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 17.990 17.990 107.023 143.003 2.285 145.288 Auxiliaries purchased MWh 17.990 17.990 107.023 143.003 2.285 145.288 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 7.39 7.39 7.39 7.39 7.39 7.39 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 689.000 689.000 689.000 2,067.000 689.000 2,756.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 55.000 55.000 55.000 165.000 55.000 220.000 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. * Indicates fuel used for testing high gas pressure trips on Units 1 & 2. 20

2011-2012 Fiscal Year-to-Date ( 4 Month ) McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 59.234 57.267 236.585 353.086 55.933 409.019 Starts # 1 1 16 18 12 30 Gross Generation MWh 561.129 564.344 18,927.359 20,052.832 1,400.897 21,453.729 Net Generation MWh 532.006 521.173 17,544.644 18,597.823 1,399.866 19,997.689 Total Auxiliaries MWh 102.563 116.611 2,127.545 2,346.719 7.715 2,354.434 Auxiliaries purchased MWh 93.555 93.555 744.830 931.940 6.684 938.624 Fuel Gas Used MMBTU 8,554.933 7,620.677 194,854.408 211,030.018 20,352.923 231,382.941 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 8,554.933 7,620.677 194,854.408 211,030.018 20,352.923 231,382.941 Net Heat Rate BTU/KWh 15,947 15,503 11,130 14,193 15,609 14,901 Unit Trips # 0 0 0 0 1 1 Capacity Factor % 0.85 0.83 4.35 3.47 0.98 2.92 Availability Factor % 81.24 81.24 81.24 81.24 81.24 81.24 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 689.000 689.000 689.000 2,067.000 689.000 2,756.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 2,203.766 2,205.733 2,026.402 6,435.901 2,207.067 8,642.968 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 139,333 139,333 277,667 277,667 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 11-12 Fuel FY 11-12 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 454,725 452,963 0 (1,762) 454,725 0 (1,762) VanSant 152,369 151,779 0 (590) 153,212 0 (1,433) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 21

VanSant Lifetime through 9/30/11 Actual Starts Factored Starts Fired Hours VanSant 1276 2205.45 4187.26 Since HGP - Dec 2004 217 537.75 803.68 Team Report: The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. In addition, they have been removing lagging and insulation at various locations on the boiler and on the Air Heater Expansion Joint. In preparation for the VanSant outage, Operations staff performed LO/TO on several pieces of equipment to expedite the start of the projected work scope. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2010-2011 Summer 2011 (June 1- Aug 31) Winter 2011-2012 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.06 1 17 * 2 17 17.67 2 17 * 3 102 102.31 3 102 * VanSant 39 39.07 11 39 * Total 175 176.11 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program 22

4.0 Maintenance During the month of October, plant maintenance staff continued addressing the backlog of work orders. There were fifty-four work orders issued with forty-six work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report October - 2011 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 17 0 3 14 2 31 8 9 30 3 54 24 2 76 4 6 0 0 6 5 24 2 0 26 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 48 20 32 36 Totals 180 54 46 188 Note: PMs are included in the priority totals Notable activities during the month include: 1) Maintenance Staff conducted inspections on Units 1 and 2 duct work, air heaters, wind boxes, steam coils, ID fans and FD fans. The inspection results revealed several cracks on the walls of the Unit 1 and 2 wind boxes. They also found two holes in the duct work on Unit 2 that will be repaired prior to the conclusion of the outage. The ID fans, FD fans and steam coils checked out with no apparent deficiencies. The air heater seals on Units 1 and 2 were found to be in “Fair” condition and need to be looked at again during the spring outage. 2) Maintenance and IC&E staff completed the replacement of the 1B Boiler Feed pump. A spare pump and motor had been sent out for refurbishment and then installed. Once the installation was completed, the pump was tested and performance data taken. The data was evaluated and it was determined that the efficiency of the rebuilt pump had increased approximately twenty percent. 3) The IC&E staff along with Teledyne (OEM for the opacity monitor) completed the yearly audit of the opacity monitors. A total of four monitors were audited, 23

three at McKee Run and one at VanSant Generating Stations. As part of the auditing process, the opacity monitors were cleaned and calibrated. There were no problems found with any of the monitors during the audit. 4) The Maintenance Staff completed the rebuild of the Unit 3 burner gas valves. The maintenance staff disassembled the gas valves and upon inspection, discovered that the O-rings in the valves had begun to degrade. They installed new O-rings, completed the rebuilt of the valves and returned them to service. 24

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: The scope of work is being planned for 2011-2012. Units 1 & 2 Cooling EG1102 Tower Life Schedule: Work planned for this fiscal year is in development. Work Extension is 1% complete. Progress: turbine repair costs for several alternatives based on turbine inspections performed in fiscal 2011have been developed and were presented to the MC committee. Final decision on how and Units 1 & 2 Life EG1107 when to proceed will be dependent of valuation study to be Extension performed.. Work planned for the refurbishment of the 1A boiler feed pump was started during the month. Schedule: Work planned for 2012 is 45% complete. Progress: The FY2011 work was completed on the expansion joint. Unit 3 Air Heater EG1112 Schedule: The FY2012 scheduled work is expected to be completed Expansion Joint by the end of November 2011. Work is presently 75% complete. Progress: Work is presently 80% complete with only minor modifications to the fuel controls remaining and expected to be Units 1 & 2 Controls EG1113 completed during the current planned outage. Modifications Schedule: The 2012 scheduled work will be completed by the end of Fiscal year. . Progress: The final gas line modifications are being made during the Unit 3 Gas Line current planned outage. Work is presently 75% complete. EG1114 Modification Schedule: All scheduled work is expected to be completed by the end of January 2012. Progress: Started on the development of the project work scope documents. Unit #3 Boiler Air EG1201 Schedule: Work scope is close to being finalized with a pre-bid Heater meeting to be scheduled in the January time period. The project is approximately 5% complete. Progress: Started on the development of the project work scope Unit #3 Boiler EG1202 documents. Completion percentage is currently 2% complete Systems Schedule: Planning for 2011-2012 fiscal year has started.. Progress: Started on the development of the project work scope documents which is expected to be completed by November 2011. Unit 3 FD & ID Fan Work is presently 5% complete. EG1203 Damper Upgrade Schedule: Bid package development should complete in December and award for materials in January. Installation should occur in the 2nd quarter of 2012. 25

Progress: Started on the development of the project work scope Unit 3 DCS documents. Work is presently 2% complete. EG1204 Computers & Schedule: Material procurement should occur in 1st quarter of 2012 Software Upgrades and installation to follow in the 2nd quarter of 2012. Progress: Metering pumps on the VanSant demineralizer skid were Miscellaneous replaced. EG1205 Capital Equipment Schedule: This project is for the unexpected needs that may occur Replacements during a budget year that were unexpected due to equipment failure. Progress: Started on the development of the project work scope documents. Several vendors were contacted in order to determine McKee Run DI possible controls replacement schemes. Work is presently at 5% EG1206 Controls complete. Replacement Schedule: Bid package development to start in January with installation planned for April- June timeframe. Progress: The air filter purchase and installation portion of the project was completed in September 2011. Work is presently at 40% VanSant Component EG1207 complete Replacements Schedule: Inspection of the balance of equipment to be performed in the January –April timeframe. Progress: Engineering has been completed and is being reviewed McKee Run by plant staff and then will be put out for bid. Work is presently at EG1208 Switchyard Blast 5% complete. Walls Schedule: Expect to bid work in January with installation in the April – June timeframe Progress: Started on the development of the project work scope McKee Run documents. Work is 10% complete. EG1209 Structural Schedule: Bid documents to be developed in the 1st quarter of 2012 Preservation with site work to start in the 2nd quarter. Progress: Started on the development of the project work scope Unit #3 Cooling documents. Work is 2% complete. EG1210 Tower Line Schedule: This project is being reevaluated and may be rescheduled Inspection into 2013 Progress: Development of the work scope is in the process of EG1211 Unit 3 Stack Repairs commencing. Work is 2% complete. Schedule: Repairs to be completed during the spring outage. Progress: Plant Staff and NAES Turbine Services are working to finalize the work scope and specification and out for bids by the end Unit 3 Turbine of November or early December. Work is approximately 5% EG1212 Inspection complete. Schedule: Bid award expected in January with installation during the spring outage Progress: Oil filtration equipment on order and expected to be Unit 3 Auxiliary EG1213 received in December. Work is approximately 35% complete. System Components Schedule: We are currently evaluating the remaining scope item, 26

refurbishment of the unit 3 Circulating water pump to determine if it should be rescheduled to offset Capital expenses now expected to result from Insurance Company recommendations. 6.0 General Plant Information Training: Plant has scheduled OES-NA to provide a PJM-based training class for the Operations staff to aid the remaining non-PJM Certified Operators gain a better understanding of the course material that will help them achieve PJM Certification. Other operators will attend the training to acquire CEHs that will help them to retain their certification. This training is scheduled for late November. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. This month’s safety topic was “Halloween Safety”. Personnel: On October 21st, Dave Hodge successfully passed the PJM System Operator Certification exam. Mr. Hodge received a PJM shirt to commemorate his achievement for passing the PJM Operator exam. 27

Calendar of Events Date One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage October 3 to December 2, 2011 Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and VanSant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual VanSant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 EIA-860 Report April 29, 2011 Units 1, 2, and 3 Spring Outage TBD NOx Ozone Season Starts May 1, 2012 EIA-923 Report May 6, 2012 Fiscal Year 2011-2012 Ends June 30, 2012 PJM Summer Capacity Test Period June 1, 2012- August 31, 2012 Toxic Release Inventory (TRI) Annual Report July 1, 2012 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2012 NOx Ozone Season Ends September 30, 2012 7.0 Summary of NAES Performance to Date Plant Performance FY 2011-2012 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0% $91,198 $91,198 Unavailability (CU) Safety 0 0 $17,099 $17,099 Environmental 0 0 $17,099 $17,099 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes $3,420 $3,420 Unit 2 No No Yes Yes $3,420 $3,420 Unit 3 No No Yes Yes $20,520 $20,520 Unit 11 No No Yes Yes $6,840 $6,840 Total YTD 100.00% Total YTD Incentive $159,597 $159,597 Incentive % Note: Units 1, 2, 3 and 11 PJM Summer Capacity Tests have been successfully completed and would be entered into the PJM Winter Capacity Test Exemption Program. The YTD Incentive calculation reflects this information. 28

V. Appendix PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights (68,699.41) (68,699.41) Balancing Operating Reserve (1,447.00) 3,748.49 2,301.49 Balancing Spot Market Energy 36,275.15 36,275.15 Balancing Transmission Congestion 1,878.28 1,878.28 Balancing Transmission Losses 1,525.44 1,525.44 Black Start Service (6,111.93) 1,674.71 (4,437.22) Day-ahead Operating Reserve 2,969.14 2,969.14 Day-ahead Scheduling Reserve 3.71 3.71 Day-ahead Spot Market Energy 107,716.61 107,716.61 Day-ahead Transmission Congestion (22,754.53) (22,754.53) Day-ahead Transmission Losses 59,227.74 59,227.74 Expansion Cost Recovery 408.58 408.58 FERC Annual Recovery 3,170.28 3,170.28 Generation Deactivation Refund (741.04) (741.04) Inadvertent Interchange 273.44 273.44 Load Reconciliation for Balancing Operating Reserve 76.78 76.78 Load Reconciliation for FERC Annual Recovery (3.06) (3.06) Load Reconciliation for Inadvertent Interchange (10.17) (10.17) Load Reconciliation for Market Monitoring Unit (MMU) Funding (0.26) (0.26) Load Reconciliation for North American Electric Reliability Corporation (NERC) (0.47) (0.47) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service (11.60) (11.60) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund 0.99 0.99 Load Reconciliation for Reactive Services 38.40 38.40 29

Load Reconciliation for Regulation and Frequency Response Service (38.62) (38.62) Load Reconciliation for Reliability First Corporation (RFC) (0.72) (0.72) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center (0.75) (0.75) Load Reconciliation for Spot Market Energy (7,096.86) (7,096.86) Load Reconciliation for Synchronized Reserve (18.64) (18.64) Load Reconciliation for Transmission Congestion (111.27) (111.27) Load Reconciliation for Transmission Losses (404.08) (404.08) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service (4.03) (4.03) Locational Reliability 716,579.25 716,579.25 Market Monitoring Unit (MMU) Funding 176.22 176.22 Meter Error Correction (5,754.56) (5,754.56) Network Integration Transmission Service 270,969.76 270,969.76 Non-Firm Point-to-Point Transmission Service (637.78) (637.78) North American Electric Reliability Corporation (NERC) 489.90 489.90 Organization of PJM States, Inc. (OPSI) Funding 34.89 34.89 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center 1,041.90 1,041.90 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. 1,001.30 1,001.30 PJM Scheduling, System Control and Dispatch Service - Control Area Administration 9,527.70 9,527.70 PJM Scheduling, System Control and Dispatch Service - Market Support 2,155.86 2,155.86 PJM Scheduling, System Control and Dispatch Service - Market Support Offset (185.83) (185.83) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration 136.56 136.56 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. (315.27) (315.27) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration (3,474.36) (3,474.36) PJM Scheduling, System Control and Dispatch Service Refund - Market Support (794.81) (794.81) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration (47.85) (47.85) 30

PJM Settlement, Inc. 185.83 185.83 Reactive Services 40,334.57 40,334.57 Reactive Supply and Voltage Control from Generation and Other Sources Service (29,467.58) 32,156.77 2,689.19 Regulation and Frequency Response Service 12,418.79 12,418.79 Reliability First Corporation (RFC) 743.31 743.31 RPM Auction (592,549.50) (592,549.50) Synchronized Reserve 11,523.80 11,523.80 Transmission Enhancement 10,506.33 10,506.33 Transmission Losses (32,914.11) (32,914.11) Transmission Owner Scheduling, System Control and Dispatch Service 4,183.85 4,183.85 Balancing Operating Reserve for Load Response 18.42 18.42 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding (0.03) (0.03) Load Reconciliation for Day-ahead Scheduling Reserve (15.00) (15.00) Load Reconciliation for Synchronous Condensing (0.20) (0.20) Emergency Load Response (3.85) (3.85) Demand Resource and ILR Compliance Penalty (6,774.42) (6,774.42) Grand Total $ (629,576.01) $1,182,359.17 $ 552,783.16 31

The Energy Authority, Inc. Monthly Management Committee Update – November 2011 December 21, 2011 Prepared by: Jamie Mahne Member Services Manager 904.360.1374 jmahne@teainc.org

TABLE OF CONTENTS I. Executive Summary ................................................................................................................ 1 II. Budget Report ......................................................................................................................... 4 III. Energy Management ............................................................................................................ 6 IV. Operations Management .....................................................Error! Bookmark not defined. i

I. Executive Summary Power Supply: Power Supply Costs FY2011-12 $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Budget Actual Powers Supply costs were $213,840 under budget due to lower load than forecast and lower than forecasted PJM prices. Average cost/MWh on the supply side was $85.74 compared to a budgeted cost of $89.01. Dover’s hedge purchases totaled 44,4500 MWh, which was 82% of the projected load. This also totaled 82% of actual load. Dover’s power purchases from hedge transactions totaled $2,988,221. Purchases from PJM totaled $760,272 (all in), with DA Energy purchases totaling $268,767 and Balancing Spot Market Energy totaling $31,535. 1

Generation Summary: Generation Revenue FY2011-12 $2,000,000 $1,500,000 $1,000,000 $500,000 $- Jul-11 Aug-11Sep-11 Oct-11 Nov- Dec-11 Jan-12 Feb-12 Mar- Apr-12 May- Jun-12 11 12 12 Budget Actual Dover did not generate electricity for PJM in the month. This was consistent with the budget. Net generation revenue was $278,219 vs. a budget of $96,057. The majority of this delta was due to lower than expected O&M costs. Operations Management Summary: During the month of November, there were no reportable or lost time accidents or injuries. The facility has now gone 412 days without an OSHA recordable accident and 412 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There was one Near Miss incident which involved the accidental discharge of the fire suppression system in the VanSant Unit 11 turbine enclosure. This discharge occurred while two employees were troubleshooting turbine control system alarms. In the month of November, McKee Run Units 1,2, and 3 and VanSant Unit 11 were not dispatched. All units were in outage starting October 3 and scheduled to complete December 2. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of November were $329,080. The expenses were $78,155 or 19.19% under the approved budget of $407,235. The principal reason for the favorable variance is due to lower labor and burden costs attributable to open staff positions and employee incentive accumulator costs budgeted in November to be paid in June 2012. 2

Risk Management Summary: Forward power prices in PJM have been falling throughout October and into November, but not as steeply as natural gas prices have fallen. Subsequently, the PJM heat rate remains very strong. Natural gas storage has risen to the top of the 5 year range. The current projected cost of service is below: Power Year Hedge Ratio Blended Cost ($/MWh) 2011-12 83% $69.12 2012-13 77% $65.45 2013-14 46% $56.10 2014-15 27% $53.59 2015-16 7% $55.33 3

II. Budget Report Variance Report: Budget Actual Variance Nov-11 Nov-11 Load Forecast (Net of Solar Output) 54,392 53,969 422 Power Supply Power Supply (inc. Mgt Fees) $4,167,762 $3,933,901 $233,861 Capacity UCAP Obligated Purchased $673,416 $693,437 ($20,021) Total - Power Supply $4,841,178 $4,627,338 $213,840 Power Generation O&M & Fixed Fuel Plant O&M $407,235 $329,080 $78,155 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation O&M & Fixed Fuel $407,235 $329,080 $78,155 Power Generation Production Margin Economic and reliability dispatch $0 $1,715 ($1,715) Testing $0 $0 $0 Subtotal Generation Production Margin $0 $1,715 ($1,715) Power Generation Non-Production Revenue Generation Capacity Credit ($555,465) ($573,435) $17,970 Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($33,933) ($35,580) $1,647 Subtotal - Non-Production Revenue ($589,398) ($609,015) $19,617 SubTotal - Power Generation ($182,163) ($278,219) $96,057 Total - Utilities Cost $4,659,016 $4,349,118 $309,897 Unit Costs Total - Power Supply $89.01 $85.74 $3.27 Total - Power Generation ($3.31) ($5.16) $1.85 Final Cost of Service to City of Dover Ratepayers $85.70 $80.59 $5.12 4

Variance Analysis: Power Supply Dover consumed 422 MWh net below what was forecasted for the month. The decrease in load and lower than expected prices in PJM resulted in a cost of $85.74/MWh for power supply, $3.27/MWh less than budget. For the month, the city realized a favorable variance of $213,840 for power supply vs. the monthly budget. Dover Sun Park generated 197 MWh above what was forecasted. Dover Sun Park invoiced the City of Dover for 200 RECs in November. Generation Power generation had a favorable budget variance of $96,057. Plant O&M expenses had a favorable budget variance of $78,155. Power Generation Production Margin realized an unfavorable budget variance of $1,715, due to Balancing Operating Reserve at PJM being designated as a generation line item. Dover did not sell any generation output to PJM in November. 5

Variance Year-To-Date: Budget Actual Variance YTD YTD Gross Load Forecast 332,408 331,418 990 Power Supply Power Supply (inc. Mgt Fees) $26,395,975 $25,902,592 $493,383 Capacity UCAP Obligated Purchased $3,434,423 $3,529,894 ($95,470) Total - Power Supply $29,830,398 $29,432,485 $397,913 Power Generation O&M & Fixed Fuel Plant O&M $2,388,378 $2,071,650 $316,728 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation O&M & Fixed Fuel $2,388,378 $2,071,650 $316,728 Power Generation Production Margin Economic and reliability dispatch ($237,844) ($1,722,315) $1,484,471 Testing $0 $0 $0 Subtotal Generation Production Margin ($237,844) ($1,722,315) $1,484,471 Power Generation Non-Production Revenue Generation Capacity Credit ($2,832,872) ($2,708,672) ($124,200) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($169,663) ($221,909) $52,246 Subtotal - Non-Production Revenue ($3,002,534) ($2,930,581) ($71,953) SubTotal - Power Generation ($852,000) ($2,581,245) $1,729,245 Total - Utilities Cost $28,978,398 $26,851,240 $2,127,158 Unit Costs Total - Power Supply $89.73 $88.13 $1.61 Total - Power Generation ($2.50) ($7.07) $4.57 Final Cost of Service to City of Dover Ratepayers $87.23 $81.06 $6.17 6

III. Energy Management Power Supply: Power Supply Costs FY2011-12 $9,000,000 $8,000,000 $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 Jul-11 Aug-11 Sep-11 Oct-11 Nov- Dec-11 Jan-12 Feb-12 Mar- Apr-12 May- Jun-12 11 12 12 Budget Actual Dover’s total load was 53,969 MWh versus a forecasted load of 54,392 MWh. Dover’s planned and realized hedged volumes were 82% of forecast and actual, respectively. Dover’s planned energy cost/MWh of unhedged load was $120. The actual energy cost for unhedged load was $89/MWh – this decrease is due to softer than expected PJM prices. Dover’s planned energy purchase from the SunPark solar installation was 743 MWh at an all-in unit cost of $100/MWh. Dover’s actual purchase from the SunPark installation was 940 MWh at an all-in unit cost of $109. The price discrepancy is due to environmental credits (SRECs) that were produced in earlier months and invoiced in November. 7

The following is a summary of Dover’s power purchases for the month: City of Dover's Wholesale Load Volume $'s Hedges 44,450 ($2,988,221.25) PJM Charges 53,029 ($1,453,710.00) TEA Fees ($83,000.00) Dover Sun Park 3 mo. Rolling Avg. ($140,216.30) Total ($4,665,147.55) Cost to Serve $/Mwh ($87.97) Purchased power variance report: Budget Actual Variance Gross Load 54,392 53,969 422 Wholesale Load 53,648 53,029 619 Hedged Volume (MWh) 44450 44450 0 Unhedged Volume (MWh) 9,198 8,579 619 Hedged Volume (%) 82% 82% -1% SunPark Volume (MWh) 743 940 -197 SunPark Energy Cost ($/MWh) $ 100 $ 109 $ (9) Unhedged Energy Cost ($/MWh) $ 120 $ 89 $ 32 Energy Costs ($/MWh) $76.63 $72.89 $3.73 All-in Costs - Energy and Capacity ($/MWh) $89.01 $85.74 $3.27 8

Generation: Dover produced no generation in November. Dover’s production margin equaled –$1,715. City of Dover's Wholesale Generation Net Generation Mwh 0.00 All In Generation Margin PJM Bill Energy $ - PJM Capacity $ 573,435.00 Black Start, Reactive Credit, DASR & EFORp $ 35,579.51 Gas Purchases $ (1,715.43) Oil Purchases $ - Transport / Cash Out $ - Gross Margin $ 607,299.09 Production Margin Generation Production Revenues (PJM) $ - Gas Purchases $ (1,715.43) Oil Purchases $ - Transport / Cash Out $ - Gross Production Margin $ (1,715.43) $/Mwh All In Generation Margin $ - $/Mwh Generation Production Margin $ - 9

Fuel Purchases: Dover had no fuel purchases in November. Transportation and Imbalance: Dover had no transportation or imbalance fees in November. 10

Emissions: Emissions and Allowance Management Dover has elected not to include revenues from emission allowance sales in its 2011- 2012 fiscal year budget. Dover has more than sufficient allowances set aside for retirement. Due to the expiration of EPA’s Clean Air Interstate Rule (CAIR) at the end of CY2011, any unused or unsold CAIR allowances will expire without residual value. Emissions Allowance Summary through September 30, 2011 2011-2012 EMISSIONS ALLOWANCE SUMMARY SO2 NOx Allowance Allowance Sale Sale Date Action Rev.1 Allocation2 Rev. Allocation Price Price Seas. Ann. N/A 2003-2006 139 0 0 Carryover 1/1/08 2007 Carryover 549 0 0 1/1/09 2008 Carryover 2,691 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 4 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 3 12/31/09 2009 Emissions (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases Aug 2011 Revised 2010 30 30 ECMPS data 9/30/11 2011 Emissions (2) (32) (36) Pre-CAIR: 3,189 TOTAL ALLOWANCES - $0 51 74 - $0 CAIR: 3,976 1 Revenue calculations account for a $0.50/ton broker fee for SO2, a $2/ton broker fee for annual NOx and $1/ton broker fee for seasonal NOx 2 Per Clean Air Interstate Rule (CAIR), starting in 2009, NOx emissions are governed by a seasonal and annual program. 3 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 11

EPA Cross-State Air Pollution Rule or CSAPR The final CSPAR was published in the August 8, 2011 Federal Register (76 FR 48208), with an effective date of October 7, 2011. The first compliance period begins for annual SO2 and NOx allowances on January 1, 2012. CSAPR does not include compliance requirements or allowance allocations for generating units located in Delaware and Dover will not be required to submit emission allowances for annual SO2, annual NOx or Seasonal NOx for compliance years 2012 and beyond. A number of administrative and legal challenges to this new rule have been filed, however TEA cannot foresee the potential outcome of such challenges. TEA has assumed that CSAPR will become enforced as promulgated, thus releasing the City of Dover from having to comply with CSAPR in its current form. As expected, on October 12, 2011, EPA notified Dover that it will remove CAIR allowances of vintage years 2012 and greater from all AMS accounts on Friday, October 14, 2011. The only remaining allowances in Dover’s AMS account should be SO2 allowances allocated under the Acid Rain allowance program in Title IV of the Clean Air Act. The Clean Air Act Title IV provisions for SO2 will remain in effect and Dover, which does not have significant SO2 emissions, will need to continue compliance with this program. RGGI and Federal Regulatory Outlook RGGI spot allowance prices have increased slightly since last month’s report with a price mid-point of $1.97 as of December 21, 2011. The 14th RGGI auction occurred on December 7th and cleared at the reserve price of $1.89, with 63% of the 2009-2011 control period allowances offered for sale actually being sold in the auction. The 15th RGGI auction is scheduled for March 15, 2012. The EPA issued the first national standard to reduce the emissions of mercury and other air toxics emissions from power plants in an effort to protect public health interests. Although the EPA added “flexibilities” into the final rule, the steep compliance cost of the Mercury and Air Toxics Standards will likely lead to a significant number of coal- fired power plant retirements by 2015. 12

IV. Operations Management NAES Corporation Dover, Delaware November 2011 Monthly Report Training was held on site for the Operations Staff to prepare them for the PJM Generation Operations Exam 13

Table of Contents 1.0 Environmental, Health and Safety 2.0 Financial 3.0 Operations 4.0 Maintenance 5.0 CIP 6.0 General Plant Information 7.0 Summary of NAES Performance 14

1.0 Environmental, Health and Safety: During the month of November, there were no restricted work days or lost time accidents. The facility has now gone 412 days without an OSHA recordable accident or a Lost Time reportable accident. The plant received no Notice of Violations (NOVs) during the month. Plant staff members continue to work with the City of Dover, DNREC, and the DRBC on an Industrial Pre-Treatment application and permit with Kent County. Once approved, the conversion of the McKee Run NPDES discharge permit to a General Stormwater permit to address the redirection of the cooling tower discharges will be pursued. There was one Near Miss incident reported during the month of November. The Near Miss occurred on November 16, 2011 at the VanSant Generating Station while Two employees were troubleshooting several alarms that had been activated on the Control System. While troubleshooting they moved a PLC control card in the Control Cab which then caused a signal to be generated that activated the Cardox System which resulted in a discharge of the fire suppression gases. While no one was hurt, the discharge could have caused a problem had anyone been working in any of the compartments where the Cardox was discharged. Environmental, Health and Safety Statistics Month Fiscal Year to Date (November) (7/1/11-6/30/12) NOVs 0 0 Opacity Deviations 0 0 Environmental Deviations 0 3 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 1 5 Man Hours Worked 3,061.00 18,913.17 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 412 Days since last Lost Time Accident 412 Emissions (NOx & SO2) All data thru 11/30/11 15

NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 31.4 1.4 36.1 NOx Summary - Year (Jan. – Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 32.6 2.9 38.8 CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 1 29/30 0/2 earlier 2011 0 75#/48# 5/3 33/31– 3/1 0/0 - 0/0 42#/17# 2/2 Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. Note #- 2 tons (Seasonal and 4 tons (Annual) were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 11/30/2011 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 2010 and earlier 0 4815 276 0 5090* 2011 0 1850 138 1 1988* 2012 0 1850 138 0 1988 Note – * Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. 16

CO2 Allowances Summary* CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 59,805 1,699 5,796 55,708 2010 0 47,844 1,636 32,971 16,509 2011 0 35,883 1,227 17,763 19,348 2012 0 23,922 818 0 24,740 2013 0 11,961 409 0 12,370 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 17

2.0 Financial Financial – Current Month Month –November 2011 Actual Budget Variance Personnel 217,456 280,690 63,234 Materials & Supplies 10,470 5,967 (4,503) Administrative Expenses 101,154 120,578 19,424 Total $329,080 $407,235 $78,155 Financial – Fiscal Year to Date (Estimated) Number of Months – 5 Actual Budget Variance Personnel 1,070,094 1,399,206 329,112 Materials & Supplies 103,973 64,770 (39,203) Administrative Expenses 897,583 924,402 26,819 Total $2,071,650 $2,388,378 $316,728 2.1 Variance analysis: The actual expenses for November are $329,080 against a budgeted amount of $407,235 for a positive variance of $78,155 or ≈ 19.19%. The variance was due to the following: PERSONNEL EXPENSES – Lower Labor, Overtime, and Burdens accounted for a favorable monthly variance of $63,234. Open positions within the plant contributed to the lower Labor and Overtime expenses. Also included in this variance is a positive variance of $31,912 for the Employee Incentive Accumulator and Employee Incentive Burden Accumulator that will occur every month. This is due to the expenses being broken down every month instead of in June when the money is actually expensed. MATERIALS AND SUPPLIES EXPENSES- The accounts with any appreciable variances were the Security-Safety Materials and City Building Maintenance accounts which contributed to an unfavorable variance of $4,503. ADMINISTRATIVE EXPENSES – Lower than budgeted expenses in the areas of Electric, Training-Conferences-Food, Contractual Services, Boiler Systems, Continuous Emission Monitors and DCS Control Systems contributed to a favorable variance of $5,691. The latest budget forecast for the current fiscal year is $5,923,416 expensed versus a budget of $5,964,817 thereby realizing a 99.31% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips McKee Run and VanSant Generating Station were in a Planned Outage status for the month of November, so no units were dispatched. The outage is expected to be closed on December 2, 2011 and all units would then be available for dispatch. Month – November 2011 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 20.036 20.036 106.249 146.321 3.204 149.525 Auxiliaries purchased MWh 20.036 20.036 106.249 146.321 3.204 149.525 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 0.00 0.00 0.00 0.00 0.00 0.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 720.000 720.000 720.000 2,160.000 720.000 2,880.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours HW Boiler Gas Usage MMBTU 426,278 426,278 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. * Indicates fuel used for testing high gas pressure trips on Units 1 & 2. 19

2011-2012 Fiscal Year-to-Date ( 5 Month ) McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 59.234 57.267 236.585 353.086 55.933 409.019 Starts # 1 1 16 18 12 30 Gross Generation MWh 561.129 564.344 18,927.359 20,052.832 1,400.897 21,453.729 Net Generation MWh 532.006 521.173 17,544.644 18,597.823 1,399.866 19,997.689 Total Auxiliaries MWh 122.599 136.647 2,233.794 2,493.040 10.919 2,503.959 Auxiliaries purchased MWh 113.591 113.591 851.079 1,078.261 9.888 1,088.149 Fuel Gas Used MMBTU 8,554.933 7,620.677 194,854.408 211,030.018 20,352.923 231,382.941 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 8,554.933 7,620.677 194,854.408 211,030.018 20,352.923 231,382.941 Net Heat Rate BTU/KWh 15,947 15,503 11,130 14,193 15,609 14,901 Unit Trips # 0 0 0 0 1 1 Capacity Factor % 0.85 0.83 4.35 3.47 0.98 2.92 Availability Factor % 81.24 81.24 81.24 81.24 81.24 81.24 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 1409.000 1409.000 1409.000 4,227.000 1409.000 5,636.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 2,203.766 2,205.733 2,026.402 6,435.901 2,207.067 8,642.968 Hours HW Boiler Gas Usage MMBTU 426,278 426,278 Pilot Gas Usage MMBTU 139,333 139,333 277,667 277,667 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 11-12 Fuel FY 11-12 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 452,963 452,081 0 (882) 454,725 0 (2,644) VanSant 151,779 151,148 0 (631) 153,212 0 (2,064) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 20

VanSant Lifetime through 11/30/11 Actual Starts Factored Starts Fired Hours VanSant 1276 2205.45 4187.26 Since HGP - Dec 2004 217 537.75 803.68 Capacity Testing – FY 2010-2011 Summer 2011 (June 1- Aug 31) Winter 2011-2012 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.06 1 17 * 2 17 17.67 2 17 * 3 102 102.31 3 102 * VanSant 39 39.07 11 39 * Total 175 176.11 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program Team Report: Operation staff continued to work on the control room expansion project. Insulation was installed and dry wall was hung, taped, spackled, and then painted. A new ceiling was installed so the I/C, E Technicians could hang the lighting fixtures. Once complete, the expansion of Unit 3 Control Room will be more operator friendly both when the units are in operation and when the units are waiting for dispatch. The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. In addition, they have been removing lagging and insulation at various locations on the boiler and on the Air Heater Expansion Joint. In preparation for the VanSant outage, Operations staff performed LO/TO on several pieces of equipment to expedite the start of the projected work scope. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. 4.0 Maintenance During the month of November, plant maintenance staff continued addressing the backlog of work orders and completing outage activities. There were twenty-four work orders issued with ninety-three work orders being completed during the month. The table below summarizes the monthly work order activities. 21

Work Order Report November - 2011 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 15 0 6 9 2 35 0 13 22 3 84 3 21 66 4 6 0 1 5 5 24 0 7 17 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 55 20 46 29 Totals 219 23 94 148 Note: PMs are included in the priority totals Notable activities during the month include: 1) The Maintenance Staff removed and inspected the lube oil coolers and heads on Unit 3 Lube Oil Cooling System. Upon inspection, the cooler tubes and faces were found in need of cleaning and that the heads were in need of repair. Plant staff cleaned the face of the coolers and cleaned the tubes using a Goodway machine. They then flushed water through each tube to clean the remaining sediment out of the tubes that was not removed by the Goodway machine. The heads were repaired by using a material that filled in the eroded sections of the heads. The heads were then machined down to ensure the facing surface was flush. The system was tested for leaks and having found no leaks, was returned to service. 2) The IC&E Technicians installed the Christmas lights on Unit 3 Stack. The lights were illuminated on Thanksgiving evening. There are many residents in the community who enjoy and look forward to the Christmas lights installed on the stack each year. 3) The Maintenance Staff prepared the underground oil lines at VanSant in advance of performing a leak test of the lines using helium. The oil was removed from the lines and helium was injected into the lines and pressurized. The test team then started the process of checking for leaks in the system. The team detected no leaks in the underground oil line systems. This inspection has a three year interval requirement and is next inspection date is scheduled for the fall of 2014. 22

4) It was discovered during an inspection of the FD Fan inlet dampers that the bearings needed to be changed out and some repairs made to the bearing housing. The Maintenance Staff completed the change out of both sides of 3A and 3B inlet FD Fan Damper bearings and repaired the bearing housings. The dampers were then set, checked and tested for proper alignment operation. 5) The IC&E staff and a third party inspection company completed the cathodic protection inspection on the underground oil lines at VanSant. The system is working in the correct design specifications with no problems. This inspection has an annual inspection requirement. The next inspection date is scheduled for the fall of 2012. 5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: The scope of work is being planned for 2011-2012. Units 1 & 2 Cooling EG1102 Tower Life Schedule: Work planned for this fiscal year is in development. Work Extension is 1% complete. Progress: Turbine repair costs for several alternatives based on turbine inspections performed in fiscal 2011have been developed and were presented to the MC committee. Final decision on how and Units 1 & 2 Life when to proceed will be dependent of valuation study to be EG1107 Extension performed. The refurbishment of the 1A Boiler Feed Pump was completed during the month. The rebuilt pump was installed, tested and is now presently in service. Schedule: Work planned for 2012 is 50% complete. Progress: The FY2011 work was completed on the expansion joint. Unit 3 Air Heater EG1112 Schedule: The FY2012 scheduled work was completed in November Expansion Joint 2011. Work is now 100% complete. Progress: Work is presently 90% complete with only minor modifications to the fuel controls remaining and expected to be Units 1 & 2 Controls EG1113 completed during the current planned outage. Modifications Schedule: The 2012 scheduled work will be completed by the end of Fiscal year. Progress: The final gas line modifications are being made during the Unit 3 Gas Line current planned outage. Work is presently 90% complete. EG1114 Modification Schedule: All scheduled work is expected to be completed by the end of December 2011. 23

Progress: Development of the project work scope documents were Unit #3 Boiler Air completed and sent out for bids. This project is at 10% completion. EG1201 Heater Schedule: Request for bids was sent out with a pre-bid meeting set for Dec. 19 and bids to be submitted in early January 2012. Progress: Started on the development of the project work scope documents. Completion percentage is currently 10% complete Unit #3 Boiler EG1202 Schedule: work scheduled for the fall 2011 outages has been Systems completed. Remaining work activities will be completed during the spring outage Progress: Development of the project work scope documents is complete. Work is presently 7% complete. Unit 3 FD & ID Fan Schedule: Bid package development is complete and request for EG1203 Damper Upgrade bids sent out to vendors. Final quotes are due and award for materials expected in January. Installation should occur in the during the Spring 2012 outage. Progress: Work continues on the development of the project work Unit 3 DCS scope documents. Work is presently 2% complete. EG1204 Computers & Schedule: Material procurement should occur in 1st quarter of 2012 Software Upgrades and installation to follow in the 2nd quarter of 2012. Progress: Metering pumps on the VanSant demineralizer skid were replaced and the tank berm stairway was purchased but not yet Miscellaneous installed. EG1205 Capital Equipment Schedule: This project is for the unexpected needs that may occur Replacements during a budget year that were unexpected due to equipment failure. Project is 45% complete. Progress: Started on the development of the project work scope documents. Several vendors were contacted in order to determine McKee Run DI possible controls replacement schemes. Work is presently at 5% EG1206 Controls complete. Replacement Schedule: Bid package development to start in January with installation planned for April- June timeframe. Progress: The air filter purchase and installation portion of the project was completed in September 2011. Work is presently at 40% VanSant Component EG1207 complete Replacements Schedule: Inspection of the balance of equipment to be performed in the January –April timeframe. Progress: Engineering has been completed and is being reviewed by McKee Run plant staff and then will be put out for bid. Work is presently at 5% EG1208 Switchyard Blast complete. Walls Schedule: Expect to bid work in January with installation in the April – June timeframe Progress: Started on the development of the project work scope McKee Run documents. Work is 10% complete. EG1209 Structural Schedule: Bid documents to be developed in the 1st quarter of 2012 Preservation with site work to start in the 2nd quarter. 24

Progress: Started on the development of the project work scope Unit #3 Cooling documents. Work is 2% complete. EG1210 Tower Line Schedule: This project is being reevaluated and may be rescheduled Inspection into 2013 Progress: Development of the work scope is in the process of EG1211 Unit 3 Stack Repairs commencing. Work is 2% complete. Schedule: Repairs to be completed during the spring outage. Progress: Plant Staff and NAES Turbine Services have finalized the work scope and specification and is now out for bids. Pre-bid is Unit 3 Turbine EG1212 scheduled for mid December. Work is approximately 5% complete. Inspection Schedule: Bid award expected in January with installation during the spring outages in 2012 and 2013 Progress: Oil filtration equipment has been received with training on Unit 3 Auxiliary the equipment to be scheduled for January 2012. Work is EG1213 System Components approximately 40% complete. Schedule: Evaluation of the other work scope items is underway. 25

6.0 General Plant Information Training: Plant scheduled OES-NA (PJM Training Firm) to conduct onsite instruction during the week of November 28 in order to provide a PJM-based training class for the Operations staff. This was set up to aid the non-PJM Certified Operators gain a better understanding of the course material that will help them achieve PJM Certification. Other operators also attended the training to acquire CEHs that will help them to retain their certification. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. This month’s safety topic was “Work Related Hearing Loss”. Calendar of Events Date Units 1, 2, 3 and 11 Fall Outage October 3 to December 2, 2011 Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and VanSant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual VanSant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 EIA-860 Report April 29, 2011 Units 1, 2, and 3 Spring Outage TBD NOx Ozone Season Starts May 1, 2012 EIA-923 Report May 6, 2012 Fiscal Year 2011-2012 Ends June 30, 2012 PJM Summer Capacity Test Period June 1, 2012- August 31, 2012 Toxic Release Inventory (TRI) Annual Report July 1, 2012 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2012 NOx Ozone Season Ends September 30, 2012 Two Year Accident Free October 14, 2012 26

7.0 Summary of NAES Performance to Date Plant Performance FY 2011-2012 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0% $91,198 $91,198 Unavailability (CU) Safety 0 0 $17,099 $17,099 Environmental 0 0 $17,099 $17,099 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes $3,420 $3,420 Unit 2 No No Yes Yes $3,420 $3,420 Unit 3 No No Yes Yes $20,520 $20,520 Unit 11 No No Yes Yes $6,840 $6,840 Total YTD 100.00% Total YTD Incentive $159,597 $159,597 Incentive % Note: Units 1, 2, 3 and 11 PJM Summer Capacity Tests have been successfully completed and would be entered into the PJM Winter Capacity Test Exemption Program. The YTD Incentive calculation reflects this information. 27

V. Appendix PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights (66,483.30) (66,483.30) Balancing Operating Reserve 2,880.63 2,880.63 Balancing Spot Market Energy 31,535.58 31,535.58 Balancing Transmission Congestion 1,638.41 1,638.41 Balancing Transmission Losses 1,144.59 1,144.59 Black Start Service (6,111.93) 1,672.24 (4,439.69) Capacity Resource Deficiency (17.10) (17.10) Day-ahead Operating Reserve 5,844.36 5,844.36 Day-ahead Scheduling Reserve 5.85 5.85 Day-ahead Spot Market Energy 268,767.35 268,767.35 Day-ahead Transmission Congestion 19,994.17 19,994.17 Day-ahead Transmission Losses 68,592.10 68,592.10 Expansion Cost Recovery 408.60 408.60 FERC Annual Recovery 3,040.10 3,040.10 Generation Deactivation Refund (741.04) (741.04) Inadvertent Interchange 797.15 797.15 Load Reconciliation for Balancing Operating Reserve 6.90 6.90 Load Reconciliation for FERC Annual Recovery 7.12 7.12 Load Reconciliation for Inadvertent Interchange 7.02 7.02 Load Reconciliation for Market Monitoring Unit (MMU) Funding 0.65 0.65 Load Reconciliation for North American Electric Reliability Corporation (NERC) 1.10 1.10 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service 27.00 27.00 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund (2.33) (2.33) Load Reconciliation for Reactive Services 65.57 65.57 Load Reconciliation for Regulation and Frequency Response Service 39.61 39.61 Load Reconciliation for Reliability First Corporation (RFC) 1.67 1.67 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center 1.87 1.87 Load Reconciliation for Spot Market Energy 5,049.99 5,049.99 28

Load Reconciliation for Synchronized Reserve 7.29 7.29 Load Reconciliation for Transmission Congestion (259.46) (259.46) Load Reconciliation for Transmission Losses 35.47 35.47 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service 9.39 9.39 Locational Reliability 693,454.50 693,454.50 Market Monitoring Unit (MMU) Funding 169.01 169.01 Meter Error Correction 2,413.59 2,413.59 Network Integration Transmission Service 262,228.80 262,228.80 Non-Firm Point-to-Point Transmission Service (624.11) (624.11) North American Electric Reliability Corporation (NERC) 469.76 469.76 Organization of PJM States, Inc. (OPSI) Funding 33.45 33.45 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center 1,773.33 1,773.33 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. 969.00 969.00 PJM Scheduling, System Control and Dispatch Service - Control Area Administration 9,136.46 9,136.46 PJM Scheduling, System Control and Dispatch Service - Market Support 2,067.87 2,067.87 PJM Scheduling, System Control and Dispatch Service - Market Support Offset (178.20) (178.20) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration 131.16 131.16 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. (305.10) (305.10) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration (3,331.67) (3,331.67) PJM Scheduling, System Control and Dispatch Service Refund - Market Support (762.25) (762.25) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration (45.91) (45.91) 29

PJM Settlement, Inc. 178.20 178.20 Reactive Services 86,837.13 86,837.13 Reactive Supply and Voltage Control from Generation and Other Sources Service (29,467.58) 32,124.44 2,656.86 Regulation and Frequency Response Service 13,798.23 13,798.23 Reliability First Corporation (RFC) 712.78 712.78 RPM Auction (573,435.00) (573,435.00) Synchronized Reserve 17,873.48 17,873.48 Transmission Enhancement 11,935.13 11,935.13 Transmission Losses (28,461.88) (28,461.88) Transmission Owner Scheduling, System Control and Dispatch Service 4,012.08 4,012.08 Balancing Operating Reserve for Load Response 0.10 0.10 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding 0.08 0.08 Load Reconciliation for Day-ahead Scheduling Reserve 3.02 3.02 Load Reconciliation for Synchronous Condensing 0.02 0.02 Demand Resource and ILR Compliance Penalty (642.92) (642.92) PJM Annual Membership Fee 5,000.00 5,000.00 Miscellaneous Bilateral (1,338.13) (1,338.13) Grand Total $ (609,015) $ 1,453,710 $ 844,695 30